A seismic survey represents an attempt to image or map the subsurface of the earth by sending sound energy down into the ground and recording the "echoes" that return from the rock layers below. The source of the down-going sound energy might come, for example, from explosions or seismic vibrators on land, or air guns in marine environments. During a seismic survey, the energy source is placed at various locations near the surface of the earth above a geologic structure of interest. Each time the source is activated, it generates a seismic signal that travels downward through the earth, is reflected, and, upon its return, is recorded at a great many locations on the surface. Multiple source/recording combinations are then combined to create a near continuous profile of the subsurface that can extend for many miles. In a two-dimensional (2D) seismic survey, the recording locations are generally laid out along a single line, whereas in a three dimensional (3D) survey the recording locations are distributed across the surface in a grid pattern. In simplest terms, a 2D seismic line can be thought of as giving a cross sectional picture (vertical slice) of the earth layers as they exist directly beneath the recording locations. A 3D survey produces a data "cube" or volume that is, at least conceptually, a 3D picture of the subsurface that lies beneath the survey area. In reality, though, both 2D and 3D surveys interrogate some volume of earth lying beneath the area covered by the survey.
A seismic survey is composed of a very large number of individual seismic recordings or traces. In a typical 2D survey, there will usually be several tens of thousands of traces, whereas in a 3D survey the number of individual traces may run into the multiple millions of traces. Chapter 1, pages 9-89, of Seismic Data Processing by Ozdogan Yilmaz, Society of Exploration Geophysicists, 1987, contains general information relating to conventional 2D processing and that disclosure is incorporated herein by reference. General background information pertaining to 3D data acquisition and processing may be found in Chapter 6, pages 384-427, of Yilmaz, the disclosure of which is also incorporated herein by reference.
A modern seismic trace is a digital recording (analog recordings were used in the past) of the acoustic energy reflecting from inhomogeneities or discontinuities in the subsurface, a partial reflection occurring each time there is a change in the elastic properties of the subsurface materials.
The digital samples are usually acquired at 0.002 second (2 millisecond or "ms") intervals, although 4 millisecond and 1 millisecond sampling intervals are also common. Each discrete sample in a conventional digital seismic trace is associated with a travel time, and in the case of reflected energy, a two-way travel time from the source to the reflector and back to the surface again, assuming, of course, that the source and receiver are both located on the surface. Many variations of the conventional source-receiver arrangement are used in practice, e.g. VSP (vertical seismic profiles) surveys. Further, the surface location of every trace in a seismic survey is carefully tracked and is generally made a part of the trace itself (as part of the trace header information). This allows the seismic information contained within the traces to be later correlated with specific surface and subsurface locations, thereby providing a means for posting and contouring seismic data--and attributes extracted therefrom--on a map (i.e., "mapping").
The data in a 3D survey are amenable to viewing in a number of different ways. First, horizontal "constant time slices" may be taken extracted from a stacked or unstacked seismic volume by collecting all of the digital samples that occur at the same travel time. This operation results in a horizontal 2D plane of seismic data. By animating a series of 2D planes it is possible for the interpreter to pan through the volume, giving the impression that successive layers are being stripped away so that the information that lies underneath may be observed. Similarly, a vertical plane of seismic data may be taken at an arbitrary azimuth through the volume by collecting and displaying the seismic traces that lie along a particular line. This operation, in effect, extracts an individual 2D seismic line from within the 3D data volume.
Seismic data that have been properly acquired and processed can provide a wealth of information to the explorationist, one of the individuals within an oil company whose job it is to locate potential drilling sites. For example, a seismic profile gives the explorationist a broad view of the subsurface structure of the rock layers and often reveals important features associated with the entrapment and storage of hydrocarbons such as faults, folds, anticlines, unconformities, and sub-surface salt domes and reefs, among many others. During the computer processing of seismic data, estimates of subsurface rock velocities are routinely generated and near surface inhomogeneities are detected and displayed. In some cases, seismic data can be used to directly estimate rock porosity, water saturation, and hydrocarbon content. Less obviously, seismic waveform attributes such as phase, peak amplitude, peak-to-trough ratio, and a host of others, can often be empirically correlated with known hydrocarbon occurrences and that correlation applied to seismic data collected over new exploration targets.
One particular branch of seismic attribute analysis that has been given increasing attention in recent years is amplitude-versus-offset ("AVO" hereinafter, or sometimes "AVA" amplitude-variation-with-angle-of-incidence) analysis, the broad goal of which is to make more easily visible to the explorationist offset-dependent reflectivity effects that may be found in some seismic data sets. The physical principle upon which AVO analyses are based is that the reflection and transmission coefficients at the top of an acoustic impedance boundary are dependent on the angle at which the seismic signal strikes that boundary. This property is true of all rock interfaces, but varies according to the particular properties of the rocks at the reflecting boundary. By way of example, gas-filled and water-filled sands have different reflection and transmission coefficients: these coefficients are also different for differing rock types, such as limestone (as compared with sandstone). Thus, by examining changes in seismic amplitude versus incidence angle (or its surrogate, shot-receiver offset) it is sometimes possible to make inferences about the subsurface lithology of a particular reflector that often could not otherwise be obtained without drilling.
These effects can sometimes be identified visually by arranging the moved-out seismic traces from a single gather (or from a composite "super" gather that includes more than one conventional gather) in order of the offset of each trace from the shot and then visually comparing the amplitudes on the near traces with the amplitudes on the far traces at the same time point. (See, for example, page 25 of "AVO Analysis: Tutorial & Review", by J. Castagna, appearing in Offset-Dependent Reflectivity--Theory and Practice of AVO Analysis, John Castagna and Milo Backus (editors), SEG Press, pp. 3-36, 1993, the disclosure of which is incorporated herein by reference). Alternatively, various AVO attributes may be calculated from the unstacked gather, each gather conventionally yielding one AVO attribute trace. By combining many of these attribute traces, entire sections or volumes may be formed that superficially resemble conventional seismic data, but which are, in reality, displays that can be used to quickly identify AVO-type effects.
The traditional AVO-type analysis involves fitting a parametric curve (i.e., a function characterized by one or more constant coefficients) to seismic amplitudes taken from a constant time "slice" of a moved-out CMP or other (e.g., common reflection point, "CRP", or common conversion point, "CPC") gather. However, the typical parametric representation is only appropriate for use with compressional or "P" type reflections. When other seismic propagation modes are present, the fitted curve may fail to adequately model the seismic data, which might potentially lead to spurious or masked hydrocarbon indicators.
By way of explanation, seismic energy propagates through the earth in one of two modes: compressional or "P" waves and shear or "S" waves, either of which might be generated by a wide variety of seismic sources. "Converted waves" are those waves that travel first as one type of wave and then the other, the conversion between wave-types happening at any seismic discontinuity. If the conversion happens once only, from an incident P-wave to a reflected S-wave, this mode will be referred to herein as a "C-wave". Additionally, multi-path (or multiple) reflections are a well known coherent noise source in seismic processing and exploration. A multiple reflection, as is well known to those skilled in the art, arises when seismic energy arrives at the surface after being reflected from more than one interface. For example, it is quite common in offshore settings to find that the original seismic signal "bounces" between the surface of the ocean and the ocean bottom a number of times during the seismic recording. This results in a repeating waveform that appears at regular time intervals throughout every recorded seismic trace (a "multiple"), the precise time separation being determined by the depth of the water, the velocity of sound in water at the recording location, and the shot-receiver offset. Additionally, it is also common to find interbed multiples in on-shore--and off-shore--surveys, these sorts of multiples arising when the seismic signal bounces up and down between two rock units. "Primary" reflections are P-mode waves that are reflected only once within the subsurface.
In conventional AVO analysis, these converted and multi-path reflections are regarded as coherent noise and suppressed--to the extent possible--during preparatory processing. However, this suppression is imperfect and invariably at least some energy from the unwanted modes is passed through, which energy has the potential to mask the true AVO effects and create false ones. Additionally, these modes--if not identified during pre-processing--can cause misinterpretations of the recorded seismic data and could ultimately lead to drilling a well based on an imperfect model of the subsurface.
Heretofore, as is well known in the seismic processing and seismic interpretation arts, there has been a need for a method of automatically identifying and extracting or suppressing particular seismic wave modes from the traces in a seismic survey. Additionally, this method should provide an improved method of conducting AVO analyses on seismic data. Accordingly, it should now be recognized, as was recognized by the present inventor, that there exists, and has existed for some time, a very real need for a method of seismic data processing that would address and solve the above-described problems.
Before proceeding to a description of the present invention, however, it should be noted and remembered that the description of the invention which follows, together with the accompanying drawings, should not be construed as limiting the invention to the examples (or preferred embodiments) shown and described. This is so because those skilled in the art to which the invention pertains will be able to devise other forms of this invention within the ambit of the appended claims.